1. Field of the Invention
The present invention pertains to a process for enhancing the recovery of hydrocarbon fluids using micellar-polymer floods and by thermoelastic fracturing the fluid injection region of the formation to be produced during the flood process.
2. Background
In certain enhanced oil recovery processes, it is known to inject slugs of surfactants comprising micellar type fluids behind a waterflood or water flush slug and to follow the slug of surfactant with a polymer fluid slug to sweep the less viscous and more mobile micellar fluid slug and oil-water bank toward a production well. In the early phases of a recovery process using the micellar fluid-polymer flooding technique, the injectivity rate is relatively high because the fluid viscosity of the waterflood and the pre-injection fluid are relatively low. However, micellar fluid slug viscosities can be on the order of ten to twenty times higher than the viscosity of the pre-injection fluid which typically is treated water. During the micellar fluid slug injection, the injectivity rate may decrease dramatically as the viscous micellar fluid slug is introduced into the formation being swept. Moreover, the further injection of polymer fluid slugs, having higher viscosities than the micellar fluid slugs, even further substantially decreases the injectivity rate as the injection process is carried out.
Since the effect of the injection rate of fluids during a micellar-polymer flood recovery process is generally proportional to the rate of finanacial return on invested capital, it is particularly important that the injectivity rate be relatively high. For example, depending on the price of the mineral values recoverable, and considering the characteristics of a formation to be recovered by enhanced recovery techniques, a chemical injection rate of approximately 400 barrels per day might produce a 30% return on invested capital while an injection rate of 800 barrels per day might produce approximately a 60% return on invested capital, hence a directly proportional relationship. Accordingly, a suitable technique which would increase the chemical injection rate without significantly increasing the cost of performing the recovery process or reducing the oil recovery performance of the process could easily be justified and considered highly desirable.
A significant factor in improving the injectivity of chemicals in an enhanced hydrocarbon recovery process pertains to the formation permeability. One known technique for enhancing the recovery of hydrocarbons comprises hydraulic fracturing of the formation to be produced to create fissures or cracks which are propped open by a suitable proppant material, such as sand, to allow the flow of hydrocarbon fluids to the wellbore. Publications by T. K. Perkins and J. A. Gonzalez entitled "Changes in Earth Stresses Around a Wellbore Caused by Radially Symmetrical Pressure and Temperature Gradients" and "The Effect of Thermoelastic Stresses on Injection Well Fracturing", published in The Society of Petroleum Engineers Journal, April 1984, and February, 1985, respectively, describe techniques for calculating the reduction in formation stresses and the pressures required to achieve hydraulic fracturing by the injection of relatively cold liquids into a subterranean formation which initially is at a temperature significantly greater than the temperature of the injection fluid. For example, many subterranean hydrocarbon bearing formatios may be in the range of 150.degree. F. to 200.degree. F. nominal temperature. This temperature can be reduced by injecting water, for example, at temperatures ranging from 35.degree. F. to 80.degree. F., thereby significantly reducing the horizontally directed and vertically directed stresses in the formation into which the water is being injected. This reduction in formation stresses can result in reduced pressures required to hydraulically fracture the formation which improves the effective permeability of the formation and accelerates the production of recoverble fluids.
Moreover, the length of the fracture, and hence the sweep of the fluid fronts, can be influenced by the rate of injection and the properties of the fluids being injected. The thermoelastic fracture tends to be self-correcting. If the fracture tends to propagate faster than the flood front, then the fracture is arrested because it encounters higher temperature and higher fracture pressure portions of the reservoir. Furthermore, fracture lengths could be minimized, if desired, by starting fluid injection at low rates, and gradually increasing the rate as the region of increased pressure expands around the injection well.
U.S. Pat. No. 4,476,932 to L. W. Emery and assigned to the assignee of the present invention also suggests that the fracturing of a formation can be enhanced by injecting cold fluid into a desired region to be fractured while isolating that region or fracturing by the further injection of a warm liquid adjacent to the zone to be fractured. Although cold fluid injectin has been suggested as a way to reduce fracture pressures, the prior art has failed to recognize or suggest such a technique for increasing formation permeability in chemical flooding processes. Accordingly, it it an object of the present invention to provide an improved enhanced oil recover process utilizing thermoelastic fracturing of a subterranean formation during a fluid sweep of the formation utilizing micellar fluids and/or polymer fluids to recover hydrocarbon fluids trapped in the formation region which is desired to be produced.